Use of Underground Access to Improve Steam Distribution in SAGD Operations

ABSTRACT

A system for recovering hydrocarbons from a subterranean formation with steam-assisted gravity drainage comprises a subterranean access tunnel extending through the formation. In addition, the system comprises a steam injection well extending through the formation above a portion of the tunnel. Further, the system comprises a production well extending through the formation above the portion of the tunnel. Still further, the system comprises a plurality of horizontally spaced bores extending upward from the access tunnel through the formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional patent application Ser. No. 61/684,061 filed Aug. 16, 2012, and entitled “Use of Underground Access to Improve Steam Distribution in SAGD Operations,” which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

This disclosure relates generally to steam-assisted gravity drainage (SAGD) techniques for producing viscous hydrocarbons. More particularly, the invention relates to the use of underground access tunnels to improve steam distribution in SAGD production operations.

As existing reserves of conventional light liquid hydrocarbons (e.g., light crude oil) are depleted and prices for hydrocarbon products continue to rise, there is a push to find new sources of hydrocarbons. Viscous hydrocarbons such as heavy oil and bitumen offer an alternative source of hydrocarbons with extensive deposits throughout the world. In general, hydrocarbons having an API gravity less than 22° are referred to as “heavy oil” and hydrocarbons having an API gravity less than 10° are referred to as “bitumen.” Although recovery of heavy oil and bitumen present challenges due to their relatively high viscosities, there are a variety of processes that can be employed to recover such viscous hydrocarbons from underground deposits.

Many techniques for recovering heavy oil and bitumen utilize thermal energy to heat the hydrocarbons, decrease the viscosity of the hydrocarbons, and mobilize the hydrocarbons within the formation, thereby enabling the extraction and recovery of the hydrocarbons. Accordingly, such production and recovery processes may generally be described as “thermal” techniques. A steam-assisted gravity drainage (SAGD) operation is one thermal technique for recovering viscous hydrocarbons such as bitumen and heavy oil. SAGD operations typically employ two vertically spaced horizontal wells drilled into the reservoir. Steam is injected into the formation via the upper well, also referred to as the “injection well,” to form a steam chamber that extends radially outward and upward from the injection well. Thermal energy from the steam reduces the viscosity of the viscous hydrocarbons, thereby enabling them to flow downward through the formation under the force of gravity. The mobilized hydrocarbons drain into the lower well, also referred to as the “production well.” The hydrocarbons collected in the production well are produced to the surface with artificial lift techniques.

Barriers in the formation, such as shale barriers, present production challenges in cases where the barrier is vertically positioned between the horizontal SAGD wells and the hydrocarbon bearing reservoir or a portion of the hydrocarbon bearing reservoir. In particular, such barriers can block the flow of steam through the formation and/or limit drainage of hydrocarbons into the production well. Accordingly, barriers in the formation can have a negative impact on overall production. Unfortunately, there are limited options for addressing such shale barriers. One proposed approach is to “hit” relatively thin shale barriers with sufficient steam and associated thermal energy to heat up the shale and liberate water retained therein. In some cases, a sufficient loss of water causes the shale barrier to shrink, thereby initiating and/or opening vertical fractures in the shale that allow the subsequent passage of steam and drainage of hydrocarbons therethrough. However, this approach is generally effective only with relatively thin shale barriers less than about six feet thick. Another possible approach is to utilize hydraulic fracturing techniques (fracking) to propogate fractures in the barrier. However, such approaches may not be available or permitted in environmentally sensitive areas.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a system for recovering hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD), the formation including a fluid impermeable barrier and a hydrocarbon reservoir having at least a portion positioned above the barrier. In an embodiment, the system comprises a subterranean access tunnel extending through the formation. In addition, the system comprises a steam injection well extending through the formation above a portion of the tunnel. Further, the system comprises a production well extending through the formation above the portion of the tunnel. Still further, the system comprises a plurality of horizontally spaced bores extending upward from the access tunnel through the formation.

These and other needs in the art are addressed in another embodiment by a method for producing hydrocarbons from a reservoir in a subterranean formation, the reservoir having at least a portion disposed above a fluid impermeable barrier in the formation. In an embodiment, the method comprises (a) constructing an access tunnel that extends through a subterranean formation below the fluid impermeable barrier. In addition, the method comprises (b) drilling a steam injection well from the access tunnel into the formation below the fluid impermeable barrier. Further, the method comprises (c) drilling a production well from the access tunnel into the formation below the fluid impermeable barrier. Still further, the method comprises (d) drilling at least one bore upward from the access tunnel into the formation and through the fluid impermeable barrier.

These and other needs in the art are addressed in another embodiment by a method for producing hydrocarbons from a reservoir in a subterranean formation, the reservoir having at least a portion disposed above a fluid impermeable barrier in the formation. In an embodiment, the method comprises (a) flowing steam from a subterranean injection well below the fluid impermeable barrier into a bore extending upward through the fluid impermeable barrier. In addition, the method comprises (b) flowing steam upward in the bore through the fluid impermeable barrier.

Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic cross-sectional side view of an embodiment of a system in accordance with the principles described herein for producing viscous hydrocarbons from a subterranean formation with steam-assisted gravity drainage techniques;

FIG. 2 is a schematic cross-sectional end view of the system of FIG. 1 taken along section 2-2 of FIG. 1;

FIG. 3 is an enlarged partial side view of a section of the liner disposed in the production well and the injection well of FIGS. 1 and 2;

FIG. 4 is an enlarged partial side view of a section of the liner disposed in one of the vertical bores of FIG. 1; and

FIG. 5 is a schematic cross-sectional end view of the system of FIG. 1 taken along section 2-2 of FIG. 1 illustrating the injection of steam from the injection well through the formation barrier and drainage of hydrocarbons through the formation barrier into the production well.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the following description and claim to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function. Moreover, the drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Still further, reference to “up” or “down” may be made for purposes of description with “up,” “upper,” “upward,” or “above” meaning generally toward or closer to the surface of the earth, and with “down,” “lower,” “downward,” or “below” meaning generally away or further from the surface of the earth.

The use of underground access in SAGD operations in accordance with the present disclosure provides a system and a method for recovering hydrocarbons such as bitumen and heavy oil situated in oil sand beds above and below a shale barrier by providing access through the shale barrier from below to allow steam originating below the shale barrier to pass upward through the shale barrier, and allowing viscosity-reduced hydrocarbons above the shale barrier to pass downward through the shale barrier.

Referring now to FIGS. 1 and 2, an embodiment of a system 10 for producing viscous hydrocarbons (e.g., heavy oil and bitumen) from a subterranean formation 100 using steam-assisted gravity drainage (SAGD) techniques is schematically shown. Moving downward from the surface 5, formation 100 includes an upper layer of consolidated cap rock 101, a first or upper layer 105 of unconsolidated sedimentary rock (e.g., McMurray sandstone), and a second or lower layer 106 of consolidated sedimentary rock (e.g., Devonian limestone). Upper layer 105 comprises or contains a reservoir 108 of viscous hydrocarbons. An intermediate layer of sedimentary rock 107 is disposed in upper layer 105 between cap rock 101 and lower layer 106. In this embodiment, intermediate layer 107 (e.g., shale) extends horizontally across layer 105 and reservoir 108 therein, thereby dividing layer 105 and reservoir 108 into upper portions 105 a, 108 a, respectively, above intermediate layer 107 and lower portions 105 b, 108 b, respectively, below intermediate layer 107. In this embodiment, portions 105 a, 105 b is porous, thereby enabling the storage of hydrocarbons therein and allowing the flow and percolation of fluids therethrough. However, intermediate layer 107 is less porous, and thus, restricts and/or prevents the flow of fluids therethrough. Thus, intermediate layer 107 may also be described as a “barrier” and/or “fluid impermeable” as it restricts and/or prevents fluid flow between portions 105 a, 105 b of upper layer 105, and restricts and/or prevents fluid flow between portions 108 a, 108 b of reservoir 108.

Referring still to FIGS. 1 and 2, system 10 mobilizes, collects and produces viscous hydrocarbons in reservoir 108 using SAGD techniques. In this embodiment, system 10 includes a subterranean access tunnel 20, an injection well 30 extending from tunnel 20, a production well 35 extending from tunnel 20 and positioned below injection well 30, and a plurality of steam transport and assist bores 40 extending from tunnel 20. During production operations, steam is injected into upper layer 105 through well 30, viscous hydrocarbons in reservoir 108 are mobilized and drain into production well 35, and the hydrocarbons that collect in production well 35 are produced into tunnel 20, and then to the surface 5. Accordingly, wells 30, 35 may also be described as a “SAGD well pair.” As will be described in more detail below, bores 40 enhance the distribution of steam from injection well 30 into reservoir 108, and further, enhance the drainage of mobilized hydrocarbons from reservoir 108 into production well 35.

Access tunnel 20 extends downward from the surface 5 through cap rock 101, upper layer 105, and into lower layer 106. The horizontal or substantially horizontal portion of tunnel 20 in lower layer 106 is disposed at a depth D₂₀ below the base (i.e., the bottom) of reservoir 108 and layer 105. The depth D₂₀ of tunnel 20 relative to reservoir 108 depends, at least in part, on the depth of reservoir 108 and the geology of reservoir 108 (e.g., the competency and integrity of layers 105, 106, the predictability of reservoir 108, etc.). For most SAGD operations, depth D₂₀ is preferably at least 5.0 m, and more preferably between 5.0 and 50.0 m.

Wells 30, 35 extend initially upward from tunnel 20 through layer 106 into lower portion 105 b of upper layer 105, and then horizontally through lower portion 105 b of upper layer 105. Thus, the portion of tunnel 20 extending horizontally through lower layer 106 is generally disposed below wells 30, 35.

In this embodiment, access tunnel 20 is reinforced and sufficiently large to allow personnel (e.g., drilling and production personnel) to move therethough and operate therein. In addition, in this embodiment, access tunnel 20 has a generally rectangular cross-section with a horizontal width W₂₀ and a vertical height H₂₀. Width W₂₀ and height H₂₀ are each preferably between 10.0 and 20.0 m. In general, access tunnel 20 may be formed by any suitable means known in the art.

Although tunnel 20 is shown as having a rectangular cross-section in this embodiment, in general, the access tunnel (e.g., tunnel 20) can have other cross-sectional shapes including triangular, round, circular, etc. In embodiments where the access tunnel (e.g., tunnel 20) has a round or circular cross-section, the diameter is preferably between 5.0 and 15.0 m.

As previously described, wells 30, 35 extend upward from tunnel 20 through lower layer 106 into lower portion 105 b below barrier 107, and then extend generally horizontally through lower portion 105 b below barrier 107. Wells 30, 35 are coextensive, substantially parallel, and disposed below reservoir 108. Depending on the geometry of reservoir 108, each well 30, 35 can be horizontal or at a slight incline (preferably less than 10°) from horizontal. The depth of wells 30, 35 depends, at least in part, on the location of reservoir 108, and are preferably positioned within layer 105 proximal the base of reservoir 108 (e.g., between 5.0 and 50.0 m below the base of reservoir 108). In addition, injection well 30 is vertically spaced above production well 35 by a vertical distance D₃₀₋₃₅ preferably less than 10.0 m, and more preferably less than or equal to 5.0 m. Each well 30, 35 preferably has a diameter between 4.0 and 12.0 in., and more preferably about 7.0 in. In general, wells 30, 35 may be drilled through layers 105, 106 by any suitable means known in the art such as with the Oilsands UTF Rig available from Kinley Exploration of Overland Park, Kans.

Although each well 30, 35 is drilled from access tunnel 20 in this embodiment, in other embodiments, one or both of the SAGD wells (e.g., wells 30, 35) can originate from locations other than the access tunnel (e.g., tunnel 20). For example, in other embodiments, the SAGD wells are drilled from the surface (e.g., surface 5).

Referring now to FIGS. 1-3, each well 30, 35 is lined with a tubular liner 50 that extends from a first end 50 a in tunnel 20 to a second end 50 b in lower portion 105 b of layer 105 opposite end 50 a. Each liner 50 is a slotted liner including a plurality of through holes. More specifically, as best shown in FIG. 3, each liner 50 includes a plurality of uniformly circumferentially and axially spaced elongate holes or slots 51 disposed along the entire portion of liner 50 extending through layer 105. As will be described in more detail below, during production operations, steam is pumped into end 50 a of liner 50 into injection well 30, and injected into layer 105 via slots 51; and mobilized hydrocarbons drain from layer 105 into liner 50 in production well 35 via slots 51, and flow through liner 50 in production well 35 to end 50 a. Thus, liner 50 in injection well 30 may also be referred to as an “injection liner,” liner 50 in production well 30 may also be referred to as a “production liner,” end 50 a of injection liner 50 may be referred to as an “inlet,” and end 50 a of production liner 50 may be referred to as an “outlet.” It should be appreciated that by positioning ends 50 a of liners 50 in wells 30, 35 in tunnel 20, they can be easily accessed to pump steam into injection liner 50 and to collect hydrocarbons from production liner 50.

Referring again to FIGS. 1 and 2, each bore 40 extends vertically upward from tunnel 20 through lower layer 106, upper layer 105, and barrier 107. Bores 40 bores 40 extend through lower portion 105 b and barrier 107 into upper portion 105 a, and terminate in upper portion 105 a. Thus, bores 40 terminate above barrier 107, but below the surface 5. In this embodiment, bores 40 are coextensive, parallel, and arranged laterally side-by-side in a row extending along tunnel 20. Each bore 40 is spaced from each adjacent bore 40 by a horizontal distance D₄₀₋₄₀ preferably between 5.0 and 50.0 m. In addition, each bore 40 has a diameter preferably between 3.5 and 12.0 in. In general, bores 40 may be drilled upward from tunnel 20 through layers 105, 106 and barrier 170 by any suitable drilling technique known in the art such as with the Oilsands UTF Rig available from Kinley Exploration of Overland Park, Kans. or with the hydraulic drilling systems and methods available from PetroJet® Canada Inc. of Calgary, Canada. Examples of hydraulic drilling systems and methods that can be used to form bores 40 are disclosed in U.S. Patent Application Pub. No. 2012/0186875, which is hereby incorporated herein by reference in its entirety for all purposes. It should be appreciated that since bores 40 are drilled upward from tunnel 20 and do not extend to the surface 5, the footprint of system 10 at the surface and associated environmental impacts are reduced.

In this embodiment, each bore 40 is lined with a tubular liner 60 that extends from a first or lower end 60 a in tunnel 20 to a second or upper end 60 b in layer 105 above barrier 107. Each bore 40 and liner 60 extends to a distance D_(60b) measured vertically upward from barrier 107. Each distance D_(60b) is preferably 1.0 to 5.0 m. As best shown in FIG. 4, each liner 60 is a slotted liner including a plurality of uniformly circumferential and axially spaced holes of slots 61. In general, slots 61 may be limited to specific locations along each liner 60. However, a plurality of slots 61 are preferably positioned immediately above barrier 107 and a plurality of slots 61 are preferably positioned immediately adjacent and proximate to each well 30, 35. As shown in FIG. 2, in this embodiment, each liner 60 includes a first plurality of slots 61 disposed along a first section or portion 62 laterally adjacent well 35, a second plurality of slots 61 disposed along a second section or portion 63 laterally adjacent well 30, and a third plurality of slots 61 disposed along a third section or portion 64 above barrier 107. As will be described in more detail below, during production operations, steam flows from injection well 30 and injection liner 50 into each bore 40 and liner 60 via slots 51 in injection liner 50 and slots 61 in second sections 63; steam flows from each bore 40 and liner 60 into layer 105 above barrier 107 via slots 61 in third section 64; mobilized hydrocarbons flow into each bore 40 and liner 60 from layer 105 above barrier 107 via slots 61 in third section 64; and mobilized hydrocarbons flow from each bore 40 and liner 60 through layer 105 into production well 35 and production liner 50 via slots 51 in production liner 50 and slots 61 in first portion 62.

A valve 65 is provided along each liner 60 below production well 35. In this embodiment, each valve 65 is positioned immediately below production well 35, and has an “open” position allowing fluid flow therethrough and a “closed” position preventing fluid flow therethrough. Thus, valves 65 can be opened to allow fluids (e.g., steam, hydrocarbons, etc.) to be pumped into or received from liners 60 through ends 60 a, or closed to prevent fluids (e.g., steam, hydrocarbons, etc.) from being pumped into or received from liners 60 through ends 60 a. In other embodiments, valves 65 may be replaced with plugs that block fluids in liners 60 from flowing through ends 60 a into tunnel 20.

As best shown in FIG. 2, in this embodiment, tunnel 20 and wells 30, 35 are parallel and vertically arranged one-above-the-other. In particular, the longitudinal axes of tunnel 20 and wells 30, 35 lie in a common vertical plane. Thus, in this embodiment, tunnel 20 and wells 30, are not laterally offset or staggered relative to each other. However, in other embodiments, the tunnel (e.g., tunnel 20), the injection well (e.g., injection well 30), the production well (e.g., production well 35), or combinations thereof can be laterally offset relative to one or more of the others. Each bore 40 extends vertically upward from tunnel 20 and passes laterally adjacent wells 30, 35, but does not intersect either well 30, 35. Thus, bores 40, and hence liners 60 therein, are laterally offset from wells 30, 35.

Referring again to FIGS. 1 and 2, in general, system 10 can be constructed by forming tunnel 20, wells 30, 35, and bores 40 one at a time or in parallel. In one embodiment of a method for constructing system 10, access tunnel 20 is formed first by boring or drilling through formation 100, then wells 30, 35 are formed by drilling from tunnel 20 and running production liner 50 and injection liner 50 from tunnel 20. Next, bores 40 are formed by drilling upward from access tunnel 20 and then running liners 60 from tunnel 20. It should be appreciated that drilling wells 30, 35 and bores 40 from subterranean tunnel 20, as opposed to drilling from the surface, reduces the overall surface footprint of system 10 and offers the potential to significantly reduce environmental impacts.

Referring now to FIG. 5, the operation of system 10 to produce viscous hydrocarbons (e.g., bitumen and/or heavy oil) in reservoir 108 is schematically shown. More specifically, steam is pumped from tunnel 20 through injection well 30 and injection liner 50, and injected into lower portion 105 b of layer 105 below barrier 107 via slots 51 in injection liner 50. The steam and associated hot water percolate through lower portion 105 b, thereby forming a steam chamber 110 that extends horizontally outward and vertically upward from injection well 30 to barrier 107. Thus, steam chamber 110 is generally shaped like an inverted triangular prism that extends along and upward from injection well 30. Steam chamber 110 does not extend through barrier 107 as barrier 107 restricts and/or prevents the passage of steam.

A portion of the steam in steam chamber 110 migrates into bores 40 and liners 60 below barrier 107 via slots 61 in second sections 63 of liners 60 extending through lower portion 105 b of layer 105. The steam that migrates into bores 40 and liners 60 below barrier 107 flows upward within bores 40 and liners 60 through barrier 107, and is injected into upper portion 105 a above barrier 107 from bores 40 and liners 60 via slots 61 in third sections 64 of liners 60 extending through upper portion 105 a of layer 105. The steam injected into upper portion 105 a from sections 64, as well as associated hot water, percolate through upper portion 105 a above barrier 107, thereby forming a plurality of steam chambers 111. Each steam chamber 111 extends radially/laterally outward and vertically upward from third section 64 of the corresponding liner 60. Thus, each steam chamber 111 is generally shaped like an inverted cone extending upward from the corresponding bore 40. In this embodiment, bores 40 are horizontally/laterally spaced sufficiently close together that each chamber 111 intersects each adjacent chamber 111, thereby forming a continuous steam chamber 112 extending through upper portion 105 a above barrier 107 generally parallel to chamber 110. In the manner described, vertical bores 40 and liners 60 enhance steam distribution in formation 100, allowing the steam to pass through and above barrier 107 and form steam chambers 111, 112 in portion 105 a above barrier 107.

Referring still to FIG. 5, thermal energy from steam chambers 111, 112 reduces the viscosity of the viscous hydrocarbons in portion 108 a of reservoir 108 to a sufficient extent to allow them to flow under the force of gravity downward through upper portion 105 a of layer 105. Barrier 107 substantially blocks the continued downward flow of the viscosity-reduced (i.e., mobilized) hydrocarbons. However, the mobilized hydrocarbons flow into bores 40 and liners 60 above barrier 107 via slots 61 in third sections 64 of liners 60, and then downward through barrier 107 within liners 60 and bores 40. With valves 65 closed, the hydrocarbons in liners 60 do not flow directly into tunnel 20, but rather, accumulate within liners 60, and exit liners 60 and bores 40 into lower portion 105 b of layer 105 via slots 61 in first sections 62 and/or second sections 63 in liners 60.

Thermal energy from steam chamber 110 reduces the viscosity of the viscous hydrocarbons in portion 108 b of reservoir 108 to a sufficient extent to allow them to flow under the force of gravity downward through lower portion 105 b of layer 105. In addition, thermal energy from steam chamber 110 reduces the viscosity of the viscous hydrocarbons exiting liners 60 into lower portion 105 b and allows them to flow under the force of gravity downward through lower portion 105 b of layer 105. The mobilized hydrocarbons in lower portion 105 b drain into production well 35 and production liner 50 via slots 51 in production liner 50. The hydrocarbons collect in production well 35, and are produced into tunnel 20 via end 50 a and then produced to the surface 5 via artificial lift (e.g., pumps). Thus, in the manner described, vertical bores 40 provide a conduit that enables steam and hydrocarbons to pass through barrier 107, thereby enhancing production from upper portion 108 a of reservoir 108 above barrier 107. It should be appreciated that in other embodiments, steam can be directly injected into vertical bores 40 from access tunnel 20 and/or hydrocarbons can be produced through vertical bores 40 to access tunnel 20.

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps. 

What is claimed is:
 1. A system for recovering hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD), the formation including a fluid impermeable barrier and a hydrocarbon reservoir having at least a portion positioned above the barrier, the system comprising: a subterranean access tunnel extending through the formation; a steam injection well extending through the formation above a portion of the tunnel; a production well extending through the formation above the portion of the tunnel; and a plurality of horizontally spaced bores extending upward from the access tunnel through the formation.
 2. The system of claim 1, wherein the portion of the access tunnel, the steam injection well, and the production well are each positioned below the fluid impermeable barrier; and wherein the bores extend through the fluid impermeable barrier.
 3. The system of claim 2, wherein the steam injection well and the production well extend from the access tunnel.
 4. The system of claim 3, wherein the steam injection well includes a portion extending horizontally through the formation; and wherein the production well includes a portion extending horizontally through the formation.
 5. The system of claim 3, wherein the steam injection well is vertically spaced above the production well.
 6. The system of claim 5, wherein the portion of the access tunnel extends horizontally through the formation.
 7. The system of claim 6, wherein the bores are configured to transport steam from the steam injection well to the portion of the hydrocarbon reservoir above the barrier.
 8. The system of claim 7, wherein the bores are configured to transport hydrocarbons from the portion of the hydrocarbon reservoir above the barrier to the production well.
 9. The system of claim 2, wherein the bores are laterally spaced from the steam injection well and the production well.
 10. The system of claim 2, wherein a slotted liner is disposed in each bore.
 11. The system of claim 10, wherein each slotted liner comprises: a first plurality of slots positioned adjacent the production well; a second plurality of slots positioned adjacent the injection well; and a third plurality of slots positioned above the fluid impermeable barrier.
 12. The system of claim 10, wherein each slotted liner includes a plug or a valve configured to prevent fluids in the liners from flowing directly into the access tunnel.
 13. A method for producing hydrocarbons from a reservoir in a subterranean formation, the reservoir having at least a portion disposed above a fluid impermeable barrier in the formation, the method comprising: (a) constructing an access tunnel that extends through a subterranean formation below the fluid impermeable barrier; (b) drilling a steam injection well from the access tunnel into the formation below the fluid impermeable barrier; (c) drilling a production well from the access tunnel into the formation below the fluid impermeable barrier; and (d) drilling at least one bore upward from the access tunnel into the formation and through the fluid impermeable barrier.
 14. The method of claim 13, further comprising: (e) flowing steam upward in the at least one bore through the fluid impermeable barrier; and (f) injecting the steam from the at least one bore into the formation above the fluid impermeable barrier after (e).
 15. The method of claim 14, further comprising: (g) flowing hydrocarbons from the portion of the reservoir above the barrier downward in the at least one bore through the fluid impermeable barrier after (f).
 16. The method of claim 15, wherein (e) further comprises: flowing steam through the injection well; and flowing steam from the injection well into the at least one bore.
 17. The method of claim 15, wherein (g) further comprises: flowing hydrocarbons from the at least one bore into the production well; and flowing hydrocarbons through the production well.
 18. The method of claim 13, further comprising: running a slotted liner through the production well; running a slotted liner through the injection well; and running a slotted liner through the at least one bore.
 19. A method for producing hydrocarbons from a reservoir in a subterranean formation, the reservoir having at least a portion disposed above a fluid impermeable barrier in the formation, the method comprising: (a) flowing steam from a subterranean injection well below the fluid impermeable barrier into a bore extending upward through the fluid impermeable barrier; and (b) flowing steam upward in the bore through the fluid impermeable barrier.
 20. The method of claim 19, further comprising: (c) flowing hydrocarbons from the reservoir into the bore after (b); (d) flowing hydrocarbons downward in the bore through the fluid impermeable barrier; and (e) flowing hydrocarbons from the bore into a subterranean production well below the fluid impermeable barrier.
 21. The method of claim 19, wherein (a) comprises: (a1) flowing steam from an injection liner disposed in the injection well through a slot in the injection liner into the formation; (a2) flowing steam in the formation into the bore through a slot of a liner disposed in the bore.
 22. The method of claim 20, wherein (e) comprises: (e1) flowing hydrocarbons from a liner disposed in the bore through a slot in the liner into the formation; and (e2) flowing hydrocarbons in the formation into a production liner disposed in the production well through a slot in the production liner. 